From the Philippines to New Zealand, nations speed up their energy licensing programs to attract players of all sizes to large oil and gas reserves at costs affordable to companies from large majors to small independents and national oil companies.
The Philippine Islands wants to reach 60% energy efficiency by 2010 under the Philippine
|A Malaysian technician works Shell Exploration and Production’s smart field platform offshore Brunei. (Photo courtesy of Shell Exploration and Production)
Energy Plan 2005-2014, but that’s a tough goal considering most discoveries in the nation have not weighed heavily on the scales of international operators.
The largest gas field discovered to date was Shell’s Malampaya field. That field, conbined with Occidental’s Camago gas field, off the northwest coast of Palawan, raises gas from subsea wells to a shallowwater platform and transfers it to a nearby onshore processing plant, which relays it to power plants feeding the Luzon grid.
According to 45% partner Chevron, the project sent an average 296 MMcf/d of gas to three power plants generating 2,700 Mw of power. The project also produced 14,000 b/d of condensate.
So far, however, only the Philippine National Oil Corp. (PNOC) has signed a contract to produce the 35-million-bbl oil rim at Malampaya, and that company is looking for outside partners. A horizontal test well to the oil rim tested at 8 million b/d of oil.
The nation granted seven service contracts in 2006, six around Palawan and one in the Sulu Sea to the southeast. No operator drilled a well during the year, since no rigs were available, but several operators plan wells when they can get rigs.
So far, the country lists 28 active service contracts, but that doesn’t count the nine contracts from the 2006 licensing round, which were due to be awarded in September. The nation claimed reserves of 25 million bbl of oil, 2.1 Tcf of gas and 54 million bbl of condensate scattered among 16 sedimentary basins at the end of 2005.
The nine contracts in the 2006 round extend from the northern tip of Luzon to the southern border in the Sulu Sea with Malaysia and Indonesia on the island of Borneo.
Contracts generally are granted on work commitments with a government share of 60% of net production. A company can claim cost reimbursements up to 70% of gross production and carry forward unrecovered costs. Participation with Filipino companies merits further incentives. The contractor is exempted from all taxes except income tax, and that comes out of the government share. Additional fees include a bonus payment of US $300,000 at the beginning of oil or gas production.
Murphy Oil generated big news for Malaysia as the Arkansas, USA, company and partner Petronas Carigali started production in August from Kikeh field on Block K offshore Sabah at an initial rate of 20,000 b/d. The field represents Malaysia’s first deepwater discovery and its first major discovery in several years. Reserves should total around 400 million bbl of oil. Production should peak next year at around 120,000 b/d.
Murphy brought in the discovery in 4,265 ft (1,300 m) of water in 2002 about 130 miles (210 km) offshore Kota Kinabalu on the island of Borneo.
“Predrilled wells in the field will continue to be placed onstream during the remainder of
||Tugboats towed ConocoPhillips Bayu Undan platform on station in the Timor Sea in 2004. (Photo courtesy of ConocoPhillips)
2007,” said Murphy President and Chief Executive Officer Claiborne P. Deming. “We also expect first sales of our associated natural gas via a dedicated pipeline to Labuan in the first part of 2008.”
Production from both subsea and dry-tree wells on a spar platform transfer oil to an adjacent floating production, storage and offloading vessel for processing at delivery to tankers.
Murphy is the operator and 80% owner of the field.
Murphy drilled dry holes at its Bagang and Bliais prospects before finding Kikeh, but it had a series of successes after Kikeh and added the Kikeh Kecil discovery as a tie-in to Kikeh.
Among those successes offshore Sabah, it drilled Kakup on a different structure in the same block. That discovery will tie in to Shell’s Block J Gumusut discovery in 3,281 ft (1,000 m) of water. That sanctioned project should begin production in 2011 and ramp up to 150,000 b/d from an estimated 600 million bbl of oil.
Shell also brought in the Malikai-1 discovery in Block G approximately 70 miles (110 km) from Gumusut. That’s just one of four discoveries the company has completed on the block.
Murphy and others previously had conducted successful operations to the southwest offshore Sarawak, Malaysia. The company’s first well discovered West Patricia field, which produces at about 20,000 b/d from a jacket platform. Since that discovery, it has added Congkak to the production string and probably will add its Endau, Rompin and Permas oil discoveries. It also sells gas to a nearby liquefied natural gas (LNG) plant from tis Pemanis, Serandah, Gasing, Wangsa, Tiram and Sapih discoveries in the same area.
Earlier this year, Australia’s BHP Billiton entered Malaysia’s deepwater arena with the
|The Northwest Shelf group’s North Ranking platform feeds gas to the Kerratha LNG plant in Western Australia, now expanding with its fifth train. (Photo courtesy of Woodside Petroleum)
acquisition offshore blocks N and Q, approximately 109 miles (175 km) offshore Sabah in water depths of 5,250 to 9,187 ft (1,600 to 2,800 m). “We believe this is a lightly explored area where we can apply and extend our 2 decades of exploration and production experience obtained in offshore and deepwater operations from Australia, the Gulf of Mexico and elsewhere in the world,” said Rob Pascoe, vice president of global exploration.
Malaysia’s production sharing contracts are based on a complex combination of factors involving costs and production rates. The idea behind the concept gives Malaysia a larger share of production as the operator’s profitability increases.
The production sharing contract offers incentive for deepwater production.
Petronas Carigali is a mandatory partner in any producing operation.
Relations are peaceful between Malaysia and Brunei Darussalam, but they aren’t serene. Sabah and Sarawak surround Brunei on the northwestern flank of Borneo, and Brunei has its own rich oil history.
Brunei Shell Petroleum is the main force in the industry and the largest producer by far. Total and Shell Deepwater Borneo Ltd. also have exploration and production operations.
Brunei and Shell are 50:50 partners in Brunei Shell Petroleum, which exports 97% of its oil and 85% of its gas production. In all, oil and gas contribute almost 70% of the nation’s gross domestic product.
Among Shell’s strong assets in the area is Champion West field, a field that was on a typical decline until the company decided to convert it to an intelligent field. It was the first in the area to use remote operation on an unmanned platform with controls both on a nearby drilling platform and at a shore base.
More recently, the company has been drilling snake and dragon wells in the area. The Champion West area is composed of a lot of small reservoirs, individually uneconomic. The company began drilling snake wells, extended reach horizontal wells that turn horizontally to tap several of those small, isolated reservoirs.
Still more recently, it has come up with dragon wells. Like the back of a dragon or sea serpent, these extended reach wells make vertical turns up and down to penetrate several of the small reservoirs.
According to Shell, Chief Engineer Jaap Van Ballengooijen returned home to The Netherlands from his Southeast Asia post and went to lunch with his son. He saw his son use a bendable straw to slurp the last drops of a milk shake from the sides of a glass and thought that would be a great idea for a well to reach Brunei’s stranded reserves.
The company began production in Brunei in 1929 with the large Seria/Tali onshore field and has grown to nine offshore and two onshore fields that produce more than 200,000 b/d of oil and 1.1 Bcf (32.4 MMcm) of gas a day. Most of the gas production goes to five LNG trains.
Total has been involved in the country since 1986 with Maharajah Lela Jamalulalam field as its principal asset on Block B offshore Brunei.
Total planned to drill the 22,000-ft (6,710-m) high-pressure/high-temperature MLJ2-06 well to examine pay potential on its block about 15 miles (25 km) from Shell’s Champion oil field, according to the Borneo Bulletin.
It was a big deal. Brunei’s energy minister showed up at the blessing ceremonies for the
||The Thylacine platform provides gas production from the Otway Basin offshore southern Australia. (Photo courtesy of Woodside Petroleum)
specially prepared Maersk Completer jackup, along with the French ambassador and regional directors from Total and Shell, a partner in the tract. The company planned to spend between $65 million and $95 million on the project. It expects 17,000 psi pressures and 334ºF (170ºC) temperatures at the bottom of the hole.
It plans to spend up to 170 days drilling and evaluating the well.
Shell Deepwater Borneo came to Shell in 2002 as part of its acquisition of Fletcher Challenge and currently operates Block A (Bendehara Selan) and blocks C and D (Laksamana Utara and East Egret).
Shell heads up a consortium that received a contract for deepwater Block K offshore Brunei, and Total picked up a contract for adjacent Block J, both about 50 miles (80 km) from shore. Those awards were made in 2001, shortly before Murphy’s Kikeh discovery offshore Sabah near the border with Brunei.
The Malaysian government also declared rights for the deepwater blocks, which it calls L and M, and it awarded those blocks to Murphy. Murphy’s discovery on Malaysia’s Block K also overlaps part of Brunei’s Block J, according to Brunei.
The situation got sticky in 2003 when Malaysian gunboats chased away a Total vessel working on Brunei’s Block J. The usual protests followed, and now both countries await a peaceful settlement that will decide where the boundaries lie. Meanwhile, both Shell and Total have suspended operations on disputed territory.
News reports in August said the two nations had come to an agreement, but no formal announcement has been released.
Investment in Indonesia’s oil and gas industry in the first half of 2007 increased by 14%, to $8 billion, compared to the same period of 2006, said the country’s upstream regulator, BPMigas. The watchdog’s Chairman Kardaya Warnika said the first-half figure gave him confidence that the full year target of $12.96 billion will be reached. Last year investment in the sector reached $9.7 billion, and for 2008 the government is targeting $14.78 billion.
Indonesia currently produces about 1 million boe/d and plans to raise that figure to 1.3 million boe/d by 2009.
Big dollars are headed toward Indonesia, much of it in the Makassar Strait area east of Borneo and west of Sulawesi.
Chevron has committed to spend $600 million on upstream projects in 2008, including $311 million on its deepwater Ganal gas block off East Kalimantan. It recently received permission for an exploration program. The five structures identified on the block have the potential to produce 800 MMcf/d.
Chevron already is the nation’s biggest operator with production of 415,000 b/d anticipated this year, down from 440,000 b/d in 2006. Its local PT Chevron Pacific Indonesia unit started an enhanced oil recovery project at its Minas field to try to maintain production levels.
The company’s acquisition of Unocal gave it substantial gas resources in deep water in the Makassar Strait.
ConocoPhillips plans a $20 million program to explore for gas on its Kuma block offshore western Sulawesi. Other companies exploring in the area include Teleti NV on the Budong-Budong block, ExxonMobil on the Surma block and PT Marathon and Gemmatera on the Pasangkayu block.
ExxonMobil signed a production sharing contract earlier this year for the Mandar block offshore West Sulawesi. The block consists of 1 million acres (4,200 sq km) in the southern Makassar Basin from the coastline to a depth of more than 6,000 ft (2,830 m). “The Mandar block augments ExxonMobil’s acreage position in the Makassar Straits where we have a PSC in place for the Surumana block from the previous tender round,” accoding to Steve Greenlee, vice president of ExxonMobil Exploration Co.
Farther north, Eni drilled its Tulip exploratory well in its Bukat area in the Tarakan Basin in 2,625 ft (800 m) of water northeast of Borneo. It said the field had significant oil and gas deposits. The Italian company also said it was a partner with Anadarko Petroleum Corp. in Aster field, where an appraisal well tested at more than 5,000 b/d of oil.
The company plans to file a development plan for the field and start appraisal work at Tulip with an eye toward joint development of the fields.
Also in the area Aabar Petroleum of Abu Dhabi has earmarked $500 million during the next 3 years for Indonesian operations, and much of that will go into its Sebuku block on the East Kalimantan side of the Makassar Strait, according to Ogilvie’s E&P Daily. “We submitted to upsream regulator BPMigas the plan of development for Sebuku at the end of August, and clearly we are hoping for approval,” said David Woodward, chief executive.
About $140 million of the investment will develop a number of blocks, including Mengoepeh in South Sumatra. The company controls eight blocks in South Sumatra, offshore East Java, offshore East Kalimantan and Papua. Four of those blocks are producing.
One big reason for the high level of interest in the area comes from state-owned Pertamina. That company is ready to sign a deal with Japan’s Mitsubishi to build a $1.2 billion liquefied natural gas plant on the Sulawesi side of the strait.
Under the development plan, the plant will produce 2 million tonnes of LNG a year using gas from the Matindok and Senoro field, both operated by Indonesia’s Medco Energi. The fields have total reserves of approximately 2 Tcf of gas.
The state oil company also is working with Korea Gas Corp. for construction of an LNG import terminal on Java. That terminal would handle 3 million to 4 million tonnes a year.
Another LNG plant in on track to start production next year. BP Indonesia’s 14-Tcf gas field will supply the company’s Tangguh LNG plant on Papua. The company already has started development drilling in the area with 15 new wells in the works, according to BP Indonesia President Director John C. Minge. The company also is talking with investors about building a third train for the project at a cost of another $880 million on top of the $2.6 billion already committed, according to The Jakarta Post.
Still more LNG for export may be in the works with Japan’s Inpex planning a $4-million investment in the world’s first floating LNG plant, according to Asia Pulse. The gas would come from an offshore block in the Arafura Sea south of Papua. The company will submit a plan to develop the plant and its Marsella block with estimated gas reserves of 10 Tcf. If approved, the plant would have a capacity of 3.5 million tonnes of LNG a year.
Gas isn’t the only target in Indonesia. Pertamina reported discovery of an 11-million-bbl field in Randegan Utara on West Java, but first production probably won’t occur for 5 or 6 years.
Sound Oil also made an interesting discovery at its Pasundan-1 well on its Citarum block southeast of Jakarta on Java. The 10,412-ft (3,173-m) well to the Baturaja lime was tricky because of cavernous intervals between 6,770 and 6,900 ft (2,063 and 2,103 m).
The world’s newest independent country, East Timor (Timor Leste) put 11 offshore blocks up for bids in its first licensing round last year. It was a qualified success. Five companies submitted nine proposals for six of the blocks.
The nation awarded blocks A, B, C, D and E to Eni and Block K to Reliance Industries of India. Block E was considered the choice block in the round.
Now the nation is preparing for its first licensing round for onshore blocks next year. Several wells have been drilled, and the nation has identified numerous oil seeps, mostly in the south.
Also, according to an announcement by Philippine Energy Secretary Raphaeil Lotila, The Philippines and Brunei have agreed to work together on development of oil and gas projects in East Timor, said a GMA news network report. The countries were invited by East Timor government officials.
Papua New Guinea
Papua New Guinea license holder Interoil has joined Merrill Lynch and Pacific LNG Operations on a joint venture designed to make the nation an LNG exporter. They will be partners in Liquid Niuguini Gas, owner of an LNG plant that may get its natural gas feedstock from the company’s Elk and Antelope onshore gas fields. Preliminary plans call for a two-train plant with a capacity to convert 1.6 Bcf/d of gas. The partners anticipate first gas in 2012.
That may or may not be the first LNG plant in the nation. AGL Energy Ltd entered into an agreement to explore a LNG proposal which could involve earlier commercialization of its gas resources in Papua New Guinea, according to Ogilvie’s E&P Daily. AGL and the partners in the Kutubu, Agogo, Moran and Gobe fields have joined in a cost-sharing agreement with the joint venture partners in the Hides, Angore and Juha gas fields to study the project. The ExxonMobil-led LNG project studies are estimated to cost around $60 million for this phase of the project, with each partner paying its share of the costs.
The massive Greater Gorgon gas complex is big news in Australia. Chevron is the operator, but it includes Chevron’s Gorgon area fields and ExxonMobil’s Io/Jansz area fields farther off the west coast of Australia.
Plans call for a liquefied natural gas plant on Barrow Island, a nature preserve that also hosts Chevron’s oil field.
The situation at Gorgon appears a little confused. According to a Dow Jones report, Credit Suisse analysts Mark Flannery and Edward Westlake told clients they had met with ExxonMobil Chief Executive Officer Rex Tillerson, he had said the project could not move forward at current proposed costs and all partners agreed on that. They also are looking at alternatives, including moving the LNG plant location from Barrow Island.
Original calculations called for partners ExxonMobil, Chevron and Shell to invest $9.2 billion in the project. That estimate has now more than doubled.
Shell apparently is more optimistic. It recently signed a heads of agreement to supply PetroChina International Co. 1 million tonnes of LNG a year from production from the Greater Gorgon project.
Chevron is the largest holder of uncommitted gas resources in the area and also has an interest in the North West Shelf Venture and its LNG plant with exports to China, Korea and Japan. That Woodside Petroleum-operated plant is building a fifth LNG train to rase capacity to 16 million tonnes a year with commissioning scheduled next year.
It also plans an LNG project with the Browse Joint Venture to the north. The Browse fields have estimated reserves of more than 20 Tcf of gas, about half the reserves of Greater Gorgon.
The Browse project got a jump-start as Woodside Energy agreed to sell 2 million to 3 million tonnes of LNG a year to PetroChina. Startup is due between 2013 and 2015.
Still more LNG is in the works from Woodside Petroleum’s Pluto and Xena discoveries containing 5 Tcf of reserves offshore Western Australia. That $9.65-billion project plans to produce 4.3 million tonnes of LNG a year from the first train at a plant on the Burrup Peninsula with deliveries aimed at Japan, starting late in 2010. Gas from other fields in the area may feed more trains.
If those fields don’t have enough feedstock, Woodside spent $168 million for the WA-404-P permit area just west of the block with Pluto and Xena fields.
Production just keeps coming off Western Australia as BHP Billiton found a 240-ft (73-m) gas column at its Thebe-1 discovery, and BHP Billiton and Apache Corp., its partner, approved a $1.7-billion development at their Pyrenees oil project in the Exmouth sub-basin. They expect to pump first oil from the floating production, storage and offloading vessel in 2010.
Interest in the area continues to climb. Total added two offshore blocks in a licensing round that saw 11 blocks go to interested operators. Those two blocks were Total’s first investments in the Bonaparte Basin offshore northwestern Australia. Overall, the company has interests in 12 blocks, including the Ichthys gas and condensate discovery in the Browse Basin.
Winners in the bidding round came from the United States, France, China, India and Australia. The blocks are offshore Western Australia, Tasmania and the Northern Territory.
Southeastern Australia also gets a share of the action. ExxonMobil, veteran producer in the Bass Strait off the southern coast of eastern Australia, said the region will still produce oil after 20 more years and gas after 30 more yeas. The company recently concluded a $400 million seismic acquistion and infill drilling program that will add 30,000 b/d of production.
ExxonMobil and BHP Billiton have flattened the decline curve for the area at 127,000 b/d of oil. Kingfish field, Australia’s biggest oil field, has produced more than 1 billion bbl of oil.
Southern Australia may get its own LNG plan as Santos released a plan to use coalbed methane as feedstock for its Gladstone LNG project in Queensland. Initial plans call for expenditures of $4.37 billion to $6.11 billion for a 3-million to 4-million-tonne-per-year plant. Santos claims more than 4.65 Tcf of methane and other gas resources in the area.
Activity is strong in New Zealand, and it’s about to get stronger. On the production side, AWE has started oil production from its Tui field in the Taranaki Basin off the west coast of the North Island. The company is ramping up to peak production of 50,000 b/d of oil from more than 30 million bbl of reserves. It will be New Zealand’s largest oil operation.
Most eyes in New Zealand’s oilpatch are focused farther south, where the government licensed five exploration permits in the Great South Basin off the southern coast of the South Island.
ExxonMobil led a consortium that included New Zealand’s Todd Exploration and took one package. The other consortium, which included OMV, Mitsui and Thailand’s PTTEP, won three packages that totaled six blocks. Those blocks include previous discoveries. The fifth package went to New Zealand’s Greymouth Petroleum.
The companies have committed to combined work programs of nearly $950 million.
According to an article in New Zealand’s The Dominion Post, Global Resource Holdings has high hopes for its Romney prospect in deep water off the Tarakanki coast. According to the company, it could hold between 1.1 billion and 1.6 billion bbl of oil, but it may not get a well drilled until 2009 or 2010. A Geological and Nuclear Sciences Institute study also indicated Romney could contain up to 2.7 Tcf of gas.
If it proves up pre-drill estimates, the expensive field would be profitable with reserves of 100 million bbl, the company said.